Formation Dip Geo-Steering Method

ABSTRACT

A method of drilling a well that includes calculating an estimated formation dip angle, wherein said estimated formation dip angle being based on offset well data, seismic data, core data, pressure data. Next, the method includes drilling a well with a logging while drilling means so that real time logging data is generated along with drilling data and calculating an instantaneous formation dip angle. Next, real time logging data is obtained and a target formation window is projected ahead of the well path that includes a top of formation and a bottom formation. The method includes monitoring the real time logging and drilling data and drilling the well through the target formation window. The method further includes changing the estimated instantaneous formation dip based on the obtained data and adjusting the target formation top and bottom window.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of application Ser. No. 12/431,339,filed Apr. 28, 2009, which is a continuation of application Ser. No.11/705,990, filed Feb. 14, 2007, which is a continuation of applicationSer. No. 10/975,966, filed Oct. 28, 2004, now issued as U.S. Pat. No.7,191,850.

FIELD OF THE INVENTION

The present invention relates to a method of steering a drill bit, andmore specifically, but not by way of limitation, to a method ofgeo-steering a bit while drilling directional and horizontal wells.

BACKGROUND OF THE INVENTION

In the exploration, drilling, and production of hydrocarbons, it becomesnecessary to drill directional and horizontal wells. As those ofordinary skill in the art appreciate, directional and horizontal wellscan increase the production rates of reservoirs. Hence, the industry hasseen a significant increase in the number of directional and horizontalwells drilled. Additionally, as the search for hydrocarbons continues,operators have increasingly been targeting thin beds and/or seams withhigh to very low permeability. The industry has also been targetingunconventional hydrocarbon reservoirs such as tight sands, shales, andcoal.

Traditionally, these thin bed reservoirs, coal seams, shales and sandsmay range from less than five feet to twenty feet. In the drilling ofthese thin zones, operators attempt to steer the drill bit within thesezones. As those of ordinary skill in the art will recognize, keeping thewell bore within the zone is highly desirable for several reasonsincluding, but not limited to, maintaining greater drilling rates,maximizing production rates once completed, limiting water production,preventing well bore stability problems, exposing more productive zones,etc.

Various prior art techniques have been introduced. However, all thesetechniques suffer from several problems. For instance, in the oil andgas industry, it has always been an accepted technique to gather surfaceand subsurface information and then map or plot the information to givea better understanding of what is actually happening below the earth'ssurface. Some of the most common mapping techniques used today includeelevation contour maps, formation contour maps, sub sea contour maps andformation thickness (isopac) maps. Some or most of these can bepresented together on one map or separate maps. For the most part, theinformation that is gathered to produce these maps are from electriclogging and real time measurement while drilling and logging devices(gamma ray, resistivity, density neutron, sonic or acoustic, surface andsubsurface seismic or any available electric log). This type of data isgenerally gathered after a well is drilled. Additionally, measurementwhile drilling and logging while drilling techniques allow the drillerreal time access to subterranean data such as gamma ray, resistivity,density neutron, and sonic or acoustic and subsurface seismic. This typeof data is generally gathered during the drilling of a well.

These logging techniques have been available and used by the industryfor many years. However, there is a need for a technique that willutilize historical well data and real time down hole data to steer thebit through the zone of interest. There is a need for a method that willproduce, in real time during drilling, an instantaneous dip for a verythin target zone. There is also a need for a process that will utilizethe instantaneous dip to produce a calculated target window (top andbottom) and extrapolate this window ahead of the projected well path soan operator can keep the drill bit within the target zone identified bythe calculated dip and associated calculated target window. These, andmany other needs will be met by the invention herein disclosed.

SUMMARY OF THE INVENTION

A method of drilling a well is disclosed. The method includes selectinga target subterranean reservoir and estimating the formation depth ofthe target reservoir. The method further includes calculating anestimated formation dip angle of the target reservoir based on dataselected from the group consisting of: offset well data, seismic data,core data, and pressure data. Then, the top of the target reservoir iscalculated and then the bottom of the target reservoir is calculated sothat a target window is established.

The method further includes projecting the target window ahead of theintended path and drilling the well. Next, the target reservoir isintersected. The target formation is logged with a measurement whiledrilling means and data representative of the characteristics of thereservoir is obtained with the measurement while drilling means selectedfrom the group consisting of, but not limited to: gamma ray, densityneutron, sonic or acoustic, subsurface seismic and resistivity. Themethod further includes, at the target reservoir's intersection,revising the top of the target reservoir and revising the bottom of thetarget reservoir to properly represent their position in relationship tothe true stratigraphic position (TSP) of the drill bit, through dipmanipulation to match the real time log data to correlate with theoffset data, and thereafter, projecting a revised target window.

The method further comprises correcting the top of the target reservoirand the bottom of the target reservoir through dip manipulation to matchthe real time logging data to the correlation offset data todirectionally steer the true stratigraphic position of the drill bit andstay within the new calculated target window while drilling ahead. Inone preferred embodiment, the step of correcting the top and bottom ofthe target reservoir includes adjusting an instantaneous formation dipangle (ifdip) based on the real time logging and drilling data'scorrelation to the offset data in relationship to the TSP of the drillbit so that the target window is adjusted (for instance up or down,wider or narrower), to reflect the target window's real position as itrelates to the TSP of the drill bit. The method may further comprisedrilling and completing the well for production.

In the one of the most preferred embodiments, the estimated formationdip angle is obtained by utilizing offset well data that includes offsetwell data such as electric line logs, seismic data, core data, andpressure data. In one of the most preferred embodiments, therepresentative logging data obtained includes a gamma ray log.

An advantage of the present invention includes use of logs from offsetwells such as gamma ray, resistivity, density neutron, sonic oracoustic, and surface and subsurface seismic. Another advantage is thatthe present invention will use data from these logs and other surfaceand down hole data to calculate a dip for a very thin target zone. Yetanother advantage is that during actual drilling, the method hereindisclosed will produce a target window (top and bottom) and extrapolatethis window ahead of the projected well path so an operator can keep thedrill bit within the target zone identified by the ifdip and targetwindow.

A feature of the present invention is that the method uses real timedrilling and logging data and historical data to recalculate theinstantaneous dip of the target window as to its correlation of the realtime logging data versus the offset wells data in relationship to theTSP of the drill bit within the target window. Another feature is thatthe method will then produce a new target window (top and bottom) andwherein this new window is extrapolated outward. Yet another feature isthat this new window will be revised based on actual data acquiredduring drilling such as, but not limited to, the real time gamma rayindicating bed boundaries. Yet another feature is that the projectionwindow is controlled by the top of the formation of interest as well asthe bottom of the formation of interest. In other words, a new windowwill be extrapolated based on real time information adjusting the topand/or bottom of the formation of interest as it relates to the TSP ofthe drill bit within that window, through the correlation of the realtime logging and drilling data to the offset well data.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a surface elevation and formation of interest contour map withoffset well locations.

FIG. 2 is a partial cross-sectional geological view of two offset wellsand a proposed well along with a dip calculation example.

FIG. 3 is a flow chart of the method of one of the most preferredembodiments of the present invention.

FIG. 4A is a schematic view of a deviated well being drilled from a rig.

FIG. 4B is a chart of gamma ray data obtained from the well seen in FIG.4A.

FIG. 5A is the schematic seen in FIG. 4A after further extendeddrilling.

FIG. 5B is a chart of gamma ray data obtained from the well seen in FIG.5A.

FIG. 6A is the schematic seen in FIG. 5A after further extendeddrilling.

FIG. 6B is a chart of gamma ray data obtained from the well seen in FIG.6A.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring now to FIG. 1, a surface elevation with formation of interestcontour map 2 with offset well locations will now be described. As seenin FIG. 1, the subsurface top of target formation of interest (FOI)contour lines (see generally 4 a, 4 b, 4 c) are shown. Also shown inFIG. 1 are the surface elevation lines (see generally 6 a, 6 b, 6 c).FIG. 1 also depicts the offset well locations 8, 9 and 10, and as seenon the map, these offset well locations contain the target formationwindow thickness as intersected by those offset wells.

As understood by those of ordinary skill in the art, map 2 is generatedusing a plurality of tools such as logs, production data, pressurebuildup data, and core data from offset wells 8, 9 and 10. Geologist mayalso use data from more distant wells. Additionally, seismic data can beused in order to help in generating map 2.

Referring now to FIG. 2, a partial cross-sectional geological view oftwo offset wells and a proposed well 16 is shown. More specifically,FIG. 2 depicts the offset well 8 and the offset well 10. The targetformation of interest, which will be a subterranean reservoir in oneembodiment, is identified in well 8 as 12, and in well 10 as 14. Theformation of interest is shown in an up dip orientation from offsetwells 10 to 8 in relationship to the position of the proposed well 16.

The proposed well 16 is shown up dip relative to wells 8 and 10, and theformation of interest that would intersect the proposed well bore isdenoted as numeral 18. An operator may wish to drill the well boreslightly above the formation of interest, or until the top of the targetformation of interest, or through the formation of interest, andthereafter kick-off at or above the target formation of interestdrilling a highly deviated horizontal well bore to stay within thetarget formation of interest. FIG. 2 depicts wherein the formation dipangle can be readily ascertained. For instance, the angle at 20 is knownby utilizing the geometric relationship well known in the art. Forexample, the operator may use the tangent relationship, wherein thetangent is equal to the opposite side divided by the adjacent side andthe ratio is then converted to degrees; hence, the formation dip angleis easily calculated. It should be noted that other factors can be takeninto account when calculating the formation dip angle as noted earlier.Data from seismic surveys can be used to modify the formation dip angleas readily understood by those of ordinary skill in the art.

In the most preferred embodiment, the dip is calculated as follows:

([top of target in proposed well 16−top of target in offset well8]/distance between wells)×inverse tangent=dip in degrees/100′.

Therefore, assuming that the top of the target in well 16 is 2200′ TVD,the top of the target in well 8 is 2280′, and the distance between thewells is 5000′, the following calculation provides the dip angle:

([2200′−2280′]/5000′)×inverse tangent=−0.9167 degrees/100′

{note: the negative sign indicates down dip and positive sign indicatesup dip}

Referring now to FIG. 3, a flow chart of one of the most preferredembodiments of the method of the present invention is illustrated.Initially, a target formation of interest is selected 24. An estimationof the formation depth of the target formation is calculated 26utilizing known techniques and uses input data from the map 2, offsetwell data, seismic data, and contour maps (step seen generally at 28),as noted earlier. The method further includes calculating the estimatedformation dip angle 30. One of the preferred methods of determining theformation dip angle was described with reference to FIG. 2 (and as seenin the example dip calculation previously presented). Parameters used tocalculate the formation dip angle were described with reference to step28, which includes utilizing the map 2, offset well data, seismic data,etc.

Next, the method includes calculating a top of the formation of interest32 and then a bottom of the formation of interest 34. The methodcomprises projecting this top and bottom target window 36 which includesas it starting frame the top of formation 32 and the bottom of formation34. Once the target window is selected, the operator can begin drillingthe well 38. As appreciated by those of ordinary skill in the art, thedrill string will have measurement while drilling (MWD) and/or loggingwhile drilling (LWD) tools 40 which will log the formation for real timesubterranean information. The information may be resistivity, gamma ray,neutron density, etc. There will also be real time drilling data beingrecorded such as rate of penetration (ROP), torque and drag, formationreturns at the surface, rotating speed, weight on bit (WOB), etc.

Based on the observed data from the LWD tools 40 and real time drillingdata, the top and bottom of the formation will be revised 42 throughinstantaneous dip manipulation to match the real time logging anddrilling data as it correlates to the offset data, to properly representtheir position in relationship to the TSP of the drill bit. Thecalculated formation dip angle at any particular instance during thedrilling process is referred to as the instantaneous formation dip angle(ifdip). The revisions will be based on the observed data and itsrelationship to the TSP of the drill bit through the correlation of thereal time logging data versus the offset well data. The TSP isdetermined by using the real time logging data and drilling data andcorrelating it to the offset wells data to locate the TSP of the bitwithin the well's target window.

Based on where the TSP of the drill bit is, a dip will be created thatwill reposition the target window around the TSP of the drill bit. Thisdip will then be used to change the target window and project it aheadfor further drilling. In the most preferred embodiment, the data will bethe gamma ray API counts 44. Normally, the gamma ray counts indicativeof a hydrocarbon reservoir, and in this embodiment are between 0 and 50API units. With the revised top FOI and bottom FOI, a new target windowcan be projected 46. If the bit goes outside the projected window (i.e.either above the top of the formation of interest or below the formationof interest), the ifdip is incorrect and a new window, and in turn a newifdip, is calculated as per the teachings of this invention.

If the total depth has been reached (as seen in step 48), then drillingcan cease and the well can be completed using conventional completiontechniques 50. If the total depth has not been reached, then the methodincludes returning to step 38 and wherein the loop repeats i.e. thedrilling continues, LWD data is obtained, the top and bottom of the FOIis revised (42) and a new target window is generated and projected (46).

Referring now to FIG. 4A, a schematic view of a deviated well beingdrilled from a rig 96 will now be described. As will be appreciated bythose of ordinary skill in the art, a well is drilled into thesubterranean zones. The target zone is indicated by the numeral 98, andwherein the target zone 98 has an estimated formation dip angle as setout in step 30 of FIG. 3 (the calculation was previously presented).Returning to FIG. 4A, the offset well log data for zone 98 is shown innumeral 99 for the target zone wherein 99 represents the distribution ofgamma counts through the target zone 98 as based on the offset welldata.

The well being drilled is denoted by the numeral 100. The operator willdrill the well with a drill bit 102 and associated logging means such asa logging while drilling means (seen generally at 104). During thedrilling, the operator will continue to correlate the geologicformations being drilled to the offset well drilling and logging data(99) as it relates to the real time drilling and logging data. Once theoperator believes that the well 100 is at a position to kick off intothe target zone 98, the operator will utilize conventional and knowndirectional techniques to effect the side track, as will be readilyunderstood by those of ordinary skill in the art. A slant welltechnique, as understood by those of ordinary skill in the art, can alsobe employed to drill through the target zone, logging it, identify thetarget zone, plug back and sidetrack to intersect the zone horizontally.As seen at point 106, the operator, based on correlation to known data,kicks off the well 100 utilizing known horizontal drilling techniques.As seen in FIG. 4B, a chart records real time logging data, such asgamma ray counts from the well 100. The charts seen in FIGS. 4B, 5B, and6B depict three (3) columns: column I shows the true vertical depth(TVD) of the offset well's associated gamma counts previously discussedwith reference to numeral 99; column II is the actual well data fromwell 100; and, column III is the vertical drift distance of the actualwell 100 from the surface location.

Hence, at point 106, the well is at a true vertical depth of 1010′, ameasured depth of 1010′ and the gamma ray count is at 100 API units; thedepth of the bit relative to the offset well's associated gamma count is1010′. The estimated formation dip angle is calculated at point 106 bythe methods described in FIG. 3, step 30 and in the discussion of FIG.2. The correlation of the offset well data (99) to the real time loggingdata verifies that the estimated formation dip angle currently beingused accurately positions the drill bit's TSP in relationship to thetarget window. Based on this correlation, the estimated formation dipangle can be used as the ifdip to generate the target window to drillahead. As noted earlier, the ifdip is the instantaneous formation dipangle based on real time logging and drilling data correlation to offsetwell logging and drilling data as it relates to the TSP of the drillbit.

As noted earlier, the operator kicks off into the target zone 98. As perthe teachings of the present invention, a top of formation of interestand a bottom of formation of interest has been calculated via theestimated formation dip angle, which in turn defines the window.Moreover, this window is projected outward as seen by projected bedboundaries 108 a, 108 b. The LWD means 104 continues sending outsignals, receiving the signals, and transmitting the received processeddata to the surface for further processing and storage as the well 100is drilled. The top of the formation of interest is intersected andconfirms that the estimated formation dip angle used is correct. Theoperator, based on the LWD information and the formation of interest topintersection can use the current estimated formation dip and project thewindow to continue drilling, which in effect becomes the instantaneousformation dip angle (ifdip). As noted at point 110, the well is now at atrue vertical depth of 1015′, a total depth of 1316′ and the real timegamma ray count at 10 API units.

The correlation of the offset well data (99) and real time logging dataverify that the drill bit's true stratigraphic position (TSP) is withinthe target window. The ifdip, according to the teachings of the presentinvention, can be changed if necessary to shift the top and bottomwindow so they reflect the drill bit's TSP within the window. Since thegamma count reading is 10, it correlates to the offset wells (99) 10gamma count position. Therefore, the actual collected data confirms thatthe well 100, at point 110, is positioned within the target window whenthe drill bit's TSP at point 110 was achieved. The instantaneousformation dip angle (ifdip) is calculated at point 110 by the following:inv. tan. [(offset well TVD−real time well TVD)/distance betweenpoints]=−0.57 29 degrees/100′, and is used to shift the window inrelationship to the drill bit's TSP, and can now be used to project thewindow ahead so drilling can continue.

As seen in FIG. 4A, the operator continues to drill ahead. The operatoractually drills a slightly more up-dip bore hole in the window as seenat point 112. As seen in FIG. 4B, the LWD indicates that the truevertical depth is 1020′, the measured depth is 1822′ and the gamma raycount is 10 API units, confirming the projected window is correct. Theprevious instantaneous formation dip angle (ifdip) can continue to beused since the real time logging data at point 112 correlates to theoffset log data 99 as it relates to the drill bit's TSP within thetarget window, and is calculated at point 112 by the following: inv.tan. [(offset well TVD−real time well TVD)/distance betweenpoints]=−0.57 29 degrees/100′.

Referring now to FIG. 5A, a schematic representation of the continuationof the extended drilling of well 100 seen in FIG. 4A will now bedescribed. At point 114, the LWD indicates that the true vertical depthis 1021′, the measured depth is 2225′ and the real time gamma ray countis 40 API units. The vertical drift distance from the surface locationis 1200′. Thus, the correlation between the real time gamma ray countand the offset gamma ray count (99) verifies the drill bit's TSP iswithin the target window and the projected window continues to becorrect as seen by applying the already established calculation. Atpoint 116, the drill bit has stayed within the projected window, and thechart in FIG. 5B indicates that the true vertical depth is 1023′ whilethe measured depth is 2327′ and the gamma ray count is 10; the verticaldrift distance from the surface location is 1300′. Hence, as per thecorrelation procedure previously discussed, the projected window isstill correct. The instantaneous formation dip angle is calculated atpoint 116 by the following: inv. tan. [(offset well TVD−real time wellTVD)/distance between points]=−0.57 29 degrees/100′. The same ifdip canbe used to project the window ahead to continue drilling.

At point 118 of FIG. 5A, the driller has drilled ahead slightly moredown dip. The projected window indicates that the bit should still bewithin the projected window. However, the chart seen in FIG. 5Bindicates that the bit has now exited the projected window by theindication that the gamma ray counts are at 90 API units. Note that thetrue vertical depth is 1025′ and the measured depth is 2530, and thevertical drift distance is 1500′. Therefore, as per the teachings of thepresent invention, the projected window requires modification. This isaccomplished by changing the instantaneous formation dip angle (ifdip)so that the drill bit's TSP is located below the bottom of the targetwindow just enough to lineup the real time logging gamma data to theoffset well gamma data (99). This is accomplished by decreasing thetarget formation window's dip angle just enough to line up thecorrelation stated above. The instantaneous formation dip angle iscalculated at point 118 by the following: inv. tan. [(offset wellTVD−real time well TVD)/distance between points]=−0.3820 degrees/100′down dip. Based on this new formation dip angle, the top of theformation window is now indicated at 108 c and the bottom of theformation window is now indicated at 108 d. FIG. 5A indicates that thedip angle for the target reservoir does in fact change, and a new windowwith the new instantaneous formation dip angle is projected from thisstratigraphic point on and drilling can proceed. Note the previouswindow boundaries of 108 a and 108 b.

Referring now to FIG. 6A, the new window has been projected i.e. windowboundaries 108 c and 108 d. The instantaneous formation dip angle(ifdip), as per the teachings of this invention, indicate that the dipangle of the formation of interest has changed to reflect the drillbit's TSP from the correlation of real time logging and drill data tooffset data and the target formation window adjusted to the newinstantaneous formation dip angle. At point 120, the operator has begunto adjust the bit inclination so that the bit is heading back into thenew projected window. As noted earlier, the bottom formation of interest108 d and the top formation of interest 108 c have been revised. FIG. 6Bconfirms that the bit is now at a true vertical depth of 1024′ and atotal depth of 2635′ at point 120, wherein the gamma ray count is at 65units. The instantaneous formation dip angle is calculated at point 120by the following: inv. tan. [(offset well TVD−real time wellTVD)/distance between points]=−0.3820 degrees/100′. The correlationprocedure mentioned earlier of using the offset well gamma data 99 tocompare with real time data indicates that the adjustment made to thebit inclination has indeed placed the drill bit's TSP right below thenew target window's bottom. This is shown by the real time logging datagamma ray unit of 65 units (see FIG. 6B) lining up with the offsetwell's gamma ray unit of 65 units (99) below the new target formationwindow that was created with the previous instantaneous dip angle atpoint 118.

At point 122, the operator has maneuvered the bit back into theprojected window. The real time data found in FIG. 6B confirms that thebit 102 has now reentered the target zone, as well as being within theprojected window, wherein the TVD is 1026.5° and the measured depth is3136′ and the gamma ray count is now at 35 API units. The instantaneousformation dip angle (ifdip) used on the projected window is now verifiedby the correlation procedure mentioned earlier being based on theinstantaneous dip formation angle of −0.3820 degrees/100′. The point 124depicts the bit within the zone of interest according to the teachingsof the present invention. As seen in FIG. 6B, at point 124, the bit isat a true vertical depth of 1027′ and a measured depth of 3337′. Thegamma ray reads 20 API units therefore confirming that the bit is withinthe zone of interest. The instantaneous formation dip angle (ifdip) cannow be used to project the target window ahead and drilling cancontinue. The instantaneous formation dip angle is calculated at point124 by the following: inv. tan. [(offset well TVD−real time wellTVD)/distance between points]=−0.3820 degrees/100′. Any form of drillingfor oil and gas, utility crossing, in mine drilling and subterraneandrilling (conventional, directional or horizontally) can use thisinvention's method and technique to stay within a target zone window.

Although the invention has been described in terms of certain preferredembodiments, it will become apparent that modifications and improvementscan be made to the inventive concepts herein without departing from thescope of the invention. The embodiments shown herein are merelyillustrative of the inventive concepts and should not be interpreted aslimiting the scope of the invention.

1. A method of drilling a well with a bit within a target subterraneanreservoir comprising the steps of: (a) calculating an estimatedformation dip angle; (b) drilling the well with a logging while drillingmeans (Iwd) and obtaining real time data representative of thecharacteristics of the reservoir; (c) calculating a top formation ofinterest utilizing an instantaneous formation dip angle (ifdip); (d)calculating a bottom formation of interest using the ifdip, and whereinthe ifdip is calculated based on the real time representative datacorrelated to an offset well data generated from an offset well; (e)projecting a window for drilling the well; (f) producing a directionaldrilling well plans based on said window; and (g) drilling the well withthe bit within said window.
 2. The method according to claim 1 whereinthe step of calculating the ifdip includes obtaining a tangent of anamount of rise of a formation over an amount of run of the formationbased on a known distance.
 3. The method according to claim 2 furthercomprising the step of: (h) collecting and monitoring the real time datarepresentative of the characteristics of the reservoir obtained in step(b).
 4. The method according to claim 3 further comprising the step of:(i) correcting the window based on a new ifdip so that the well stayswithin the target reservoir, said new ifdip is calculated based on areal time representative data correlated to said offset well data. 5.The method according to claim 4 further comprising the steps of: (j)drilling the well; and (k) completing the well for production.